Multi-functional surfactant complexes for use in subterranean formations

ABSTRACT

Systems and methods for creating and/or using multi-functional surfactant complexes that may enhance surfactant treatments in subterranean formations are provided. In some embodiments, the methods comprise: providing a treatment fluid comprising an aqueous base fluid and one or more multi-functional surfactant complexes that comprise at least one surfactant and at least one polymeric additive, wherein the surfactant and the polymeric additive carry opposite charges; and introducing the treatment fluid into a well bore at a well site penetrating at least a portion of a subterranean formation.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to PCT Application Ser. No.PCT/US2014/49449 titled “Methods and Systems for Preparing SurfactantPolyelectrolyte Complexes for Use in Subterranean Formations” filed Aug.1, 2014, the entire disclosure of which is incorporated by referenceherein, and is continuation-in part thereof.

BACKGROUND

The present disclosure relates to systems and methods for treatingsubterranean formations using surfactants.

Treatment fluids can be used in a variety of subterranean treatmentoperations. As used herein, the terms “treat,” “treatment,” “treating,”and grammatical equivalents thereof refer to any subterranean operationthat uses a fluid in conjunction with achieving a desired functionand/or for a desired purpose. Use of these terms does not imply anyparticular action by the treatment fluid. Illustrative treatmentoperations can include, for example, fracturing operations, gravelpacking operations, acidizing operations, scale dissolution and removal,consolidation operations, and the like.

Many such treatment fluids include a variety of chemicals to treatcommon problems encountered in the subterranean formation and/or wellbore. Commonly encountered problems include the production of scaleproducing compounds, wax buildup and corrosion. To solve this widevariety of problems, the oil industry has developed several categoriesof well treatment chemicals. A non-inclusive classification of welltreatment chemicals includes: scale inhibitors, biocides, corrosioninhibitors, hydrogen sulfide scavengers, well tracing materials,de-waxing agents, clay stabilizers, and many others.

Surfactants are also widely used in treatment fluids for drillingoperations and other well treatment operations, including hydraulicfracturing and acidizing (both fracture acidizing and matrix acidizing)treatments. Surfactants may also be used in enhanced or improved oilrecovery operations. Many variables may affect the selection of asurfactant for use in such treatments and operations, such asinterfacial surface tension, wettability, compatibility with otheradditives (such as other additives used in acidizing treatments), andemulsification tendency. Surfactants are often an important component intreatment fluids for ensuring higher productivity from unconventionaloil and gas formations.

SUMMARY

The present disclosure relates to systems and methods for treatingsubterranean formations. More particularly, the present disclosurerelates to systems and methods for creating and/or usingmulti-functional surfactant complexes that may enhance surfactanttreatments in subterranean formations.

In certain embodiments, the present disclosure provides a methodcomprising: providing a first solution comprising at least onesurfactant and a second solution comprising at least one polymericadditive, wherein the surfactant and the polymeric additive carryopposite charges; using a stop-flow mixing apparatus at a well site tomix the first and second solutions to form one or more multi-functionalsurfactant complexes that comprise the surfactant and the polymericadditive; using a low-dose pumping apparatus at the well site totransfer the one or more multi-functional surfactant complexes from thestop-flow mixing apparatus to a blending apparatus at the well site;using the blending apparatus to mix the one or more multi-functionalsurfactant complexes with an aqueous base fluid to form a treatmentfluid; and introducing the treatment fluid into a well bore at the wellsite penetrating at least a portion of a subterranean formation.

In certain embodiments, the present disclosure provides a system forpreparing multi-functional surfactant complexes at a well sitecomprising: a pump and blender system disposed at a surface of a wellbore penetrating at least a portion of a subterranean formation; astop-flow mixing apparatus having at least a first inlet for receiving asolution comprising a surfactant, a second inlet for receiving asolution comprising a polymeric additive, and an outlet through which asolution comprising one or more multi-functional surfactant complexesflows out of the stop-flow mixing apparatus; a low-dose pumpingapparatus coupled between the outlet of the stop-flow mixing apparatusand an inlet of the pump and blender system; and a base fluid sourcecoupled to an inlet of the pump and blender system.

In certain embodiments, the present disclosure provides a methodcomprising: providing a treatment fluid comprising an aqueous base fluidand one or more multi-functional surfactant complexes that comprise atleast one surfactant and at least one polymeric additive, wherein thesurfactant and the polymeric additive carry opposite charges; andintroducing the treatment fluid into a well bore at a well sitepenetrating at least a portion of a subterranean formation.

The features and advantages of the present disclosure will be readilyapparent to those skilled in the art. While numerous changes may be madeby those skilled in the art, such changes are within the spirit of thedisclosure and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present disclosure, and should not be used to limit or define theclaims.

FIG. 1 is a diagram illustrating an example of a well treatment systemthat may be used in accordance with certain embodiments of the presentdisclosure.

FIG. 2 is a diagram illustrating a stop-flow mixing apparatus that maybe used in accordance with certain embodiments of the presentdisclosure.

FIG. 3 is a diagram illustrating an example of a subterranean formationin which a fracturing operation may be performed in accordance withcertain embodiments of the present disclosure.

FIG. 4 is a graph illustrating dynamic surface tension data of certainsolutions according to embodiments of the present disclosure.

FIG. 5 is a graph illustrating dynamic surface tension data of certainsolutions according to embodiments of the present disclosure.

FIGS. 6A and 6B are graphs illustrating interfacial tension data ofcertain solutions according to embodiments of the present disclosure.

FIG. 7 is a bar graph illustrating oil recovery data in tests of certainsolutions according to embodiments of the present disclosure.

While embodiments of this disclosure have been depicted, suchembodiments do not imply a limitation on the disclosure, and no suchlimitation should be inferred. The subject matter disclosed is capableof considerable modification, alteration, and equivalents in form andfunction, as will occur to those skilled in the pertinent art and havingthe benefit of this disclosure. The depicted and described embodimentsof this disclosure are examples only, and not exhaustive of the scope ofthe disclosure.

DESCRIPTION OF EMBODIMENTS

The present disclosure relates to systems and methods for treatingsubterranean formations. More particularly, the present disclosurerelates to systems and methods for creating and/or usingmulti-functional surfactant complexes that may enhance surfactanttreatments in subterranean formations.

The present disclosure provides methods and systems for creating and/orusing multi-functional surfactant complexes (MSCs) for use insubterranean formations and subterranean wells penetrating suchformations. The MSCs of the present disclosure generally comprise acomplex of surfactant molecules and molecules of an oppositely-chargedpolymeric additive, such as a friction reducer, a clay stabilizer, abiocide, a corrosion inhibitor, a scale inhibitor, or any combinationthereof associated with one another via a non-covalent (e.g., ionic)interaction. In certain embodiments, the multi-functional surfactantcomplexes of the present disclosure may be prepared by adding asurfactant and polymeric additive carrying opposite electrostaticcharges to a stop-flow mixing apparatus and mixed at an appropriatespeed to form one or more MSCs. The mixture is then transferred to ablender at a well site using a low-dose pumping apparatus. The blenderthen mixes the MSCs into a base fluid (and, optionally, additionaladditives) to prepare a treatment fluid that may be introduced into atleast a portion of a subterranean formation. In certain embodiments, oneor more of the aforementioned steps may be performed at a well site, forexample, substantially in or near real-time with the treatment and/oroperation in which the MSCs are used. The treatment fluids of thepresent disclosure thus may comprise an aqueous base fluid and one ormore multi-functional surfactant complexes. In certain embodiments, thetreatment fluid is a fracturing fluid. However, the teachings of thepresent disclosure may be used in other treatment or subterraneanfluids, including but not limited to, acidizing fluids and drillingfluids.

Without limiting the disclosure to any particular theory or mechanism,the electrostatic attraction between the oppositely charged surfactantand polymeric additive may drive the two molecules to formmulti-functional surfactant complexes (MSCs). It is believed that theMSC is kinetically stable and that surfactant molecules may betemporarily trapped by the oppositely-charged polymeric additive. Thisin turn may minimize any interactions between the surfactant/polymericadditive and other components or additives in a treatment fluid (e.g.,proppants) and/or the formation (e.g., charged rock surfaces in theformation) as the additives are pumped downhole. Thus, the surfactantand/or polymeric additive may be pumped deeper into the reservoir, atwhich point the MSCs may be disassembled or inverted through a varietyof mechanisms to release the surfactant molecules and the polymericadditive. For example, phase equilibrium of MSC may be associated withthe salinity of its environment; therefore, change of salinity couldlead to disassembly of the aggregates. Temperature gradients and/or pHchanges may also break up the MSCs and release the surfactant moleculesand polymeric additive.

Among the many potential advantages to the methods and compositions ofthe present disclosure, only some of which are alluded to herein, themethods, compositions, and systems of the present disclosure may enhancethe performance of surfactants and/or polymeric treatment additives byproviding them in a manner that allows for synergistic interactions(e.g., delayed release) between the molecules of those components. Insome embodiments, the methods and systems of the present disclosure mayincrease the penetration depth of certain treatment fluids, enabling thetreatment of deep and/or dead-end pores in certain rock or formationswhere conventional treatments may not have been able to deliversurfactants and/or other additives as effectively. The methods andsystems of the present disclosure also may provide a means of preparingMSCs for use at a well site immediately or soon after their preparation,which may allow operators to use MSCs in well treatments without theneed to transport them to the well site and before they degrade orbecome unstable. In certain embodiments, the MSCs and/or the surfactantstherein may be used in emulsions to enhance and/or prolong theirstability. In certain embodiments, the MSCs may alter the bulkviscoelastic properties of the fluid and/or may induce turbulent flowtherein. These viscoelastic properties may be tailored, among otherreasons, to engineer flow that increases the contact of a treatmentfluid of the present disclosure with oil globules in a subterraneanformation (thereby enhancing oil recovery) and/or divert treatmentfluids into deeper pores in a subterranean formation. In certainembodiments, charged MSCs may create electric fields in pore spaces in aformation that may act as “micropumps” that enhance diffusiooemotic flowin those pores.

The surfactant in the MSCs may comprise any surfactant (or blend ofmultiple surfactants) known in the art. In some embodiments thesurfactant may be anionic, while in other embodiments it may becationic, or in yet other embodiments, amphoteric, zwitterionic, ornon-ionic, respectively. In some embodiments, the desired ionization, ifany, of the surfactant may be determined based at least in part upon oneor more characteristics of the oil and/or gas of a subterraneanformation. For example, the charge of a surfactant of some embodimentsof the treatment fluid may allow the surfactant to induce pairinteractions (e.g., electrostatic interactions) with one or moremolecules of oil and/or gas in the subterranean formation.

Thus, where the oil and/or gas of a subterranean formation containspredominantly alkaline compounds, which are typically positively chargedin nature, the surfactant of some embodiments of the present disclosuremay be anionic to allow the surfactant to induce electrostatic pairinteractions with positively-charged oil and/or gas molecules. In someinstances, the oil and/or gas of a subterranean formation may contain amixture of alkaline and acidic compounds. In such a circumstance, it maybe advantageous to use an amphoteric and/or zwitterionic surfactantaccording to some embodiments of the present disclosure. Furthermore,the amphoteric and/or zwitterionic surfactants of some embodiments mayexhibit different charge and/or reactivity at different ranges of pH.For instance, some surfactants that are amphoteric and/or zwitterionicat pH less than about 2 may become anionic, cationic, or non-ionic at pHgreater than about 2. Because the downhole pH may change duringacidization (for example, pH may rise from levels of from about 0-1 toabout 4, as the acid is spent), the characteristics of surfactants ofsome embodiments may change during the process of an acidizationtreatment. Other characteristics of oil and/or gas within the formationthat might affect the determination of desired surfactant chargeinclude, but are not limited to: weight percentages of saturates,aromatics, resins and asphaltenes.

Examples of anionic surfactants that may be suitable in certainembodiments may include, but are not limited to: sodium, potassium, andammonium salts of long chain alkyl sulfonates and alkyl aryl sulfonates(such as sodium dodecylbenzene sulfonate); dialkyl sodiumsulfosuccinates (such as sodium dodecylbenzene sulfonate or sodiumbis-(2-ethylthioxyl)-sulfosuccinate); alkyl sulfates (such as sodiumlauryl sulfate); alkyl sulfonates (such as methyl sulfonate, heptylsulfonate, decylbenzene sulfonate, dodecylbenzene sulfonate); andalkoxylated sulfates. Certain embodiments of the present disclosure mayinclude a combination of anionic surfactants. Examples of non-ionicsurfactants that may be suitable in certain embodiments may include, butare not limited to: ethoxylated alcohols and polyglucosides. In someembodiments, non-ionic surfactants may include ethoxylated long-chainalcohols (e.g., ethoxylated dodecanol). Ethoxylation may take place atany point along the alcohol. Examples of cationic surfactants that maybe suitable in certain embodiments may include, but are not limited to:alkyl ammonium bromides. In some embodiments, the alkyl chain of thealkyl ammonium bromide may be anywhere from 1 to 50 carbons long, and bebranched or un-branched. Thus, an example embodiment may include analkyl ammonium bromide that comprises a 16-carbon chain alkyl component(e.g., cetyl trimethyl ammonium bromide). Examples of amphoteric and/orzwitterionic surfactants that may be suitable in certain embodiments mayinclude, but are not limited to, hydroxysultaines (e.g., cocoamidopropylhydroxysultaine, lauramidopropyl hydroxysultaine, laurylhydroxysultaine, etc.).

The polymeric additive in the MSCs of the present disclosure maycomprise any any treatment additive (or blend of multiple additives)known in the art that carries a charge opposite that of the surfactantand is capable of performing a particular treatment or function in awell bore or subterranean formation. Examples of additives that may besuitable in certain embodiments of the present disclosure include, butare not limited to, friction reducers, clay stabilizers, biocides,corrosion inhibitors, scale inhibitors, and any combination thereof.Examples of polymeric clay stabilizers that may be used to form MSCs ofthe present disclosure include, but are not limited to polydiallyldimethylammonium chloride (DADMAC),polyacrylamide-co-diallydimetylammonium chloride (AMD1 and AMD2),polyacrylic acid-co-diallydimethylammonium chloride (AAD), anddodecyltrimethylammonium bromide (DDAB). In certain embodiments,multiple different polymeric additives may be used to form MSCs with asingle surfactant and/or with multiple different surfactants. In certainembodiments, MSCs comprising different polymeric additives may be formedseparately and combined in a single treatment fluid.

In certain embodiments, the polymeric additives and/or surfactants maybe mixed in any amount and/or concentration that causes them to form oneor more MSCs. In certain embodiments, the relative concentrations ofpolymeric additive and surfactant may be varied, among other reasons, tocontrol the size and/or number of the MSCs formed, to make the MSCs morestable, to increase the reaction rate, and other factors. For example,in certain embodiments, the number of MSCs may be increased byincreasing the concentration of the polymeric additive relative to theconcentration of the surfactant. A person of skill in the art with thebenefit of this disclosure will recognize how to vary the amounts and/orconcentrations of the polymeric additives and/or surfactants to produceMSCs having the desired properties.

In certain embodiments, the polymeric additives and/or surfactants maybe provided in solutions prior to mixing, for example, using thestop-flow mixing apparatus to form the MSCs. The treatment fluids ofsome embodiments may be aqueous or organic. In certain embodiments,water may be used as a solvent for hydrophilic polymeric additives. Inother embodiments, organic solvents may be used as a solvent forhydrophobic polymeric additives.

Examples of organic solvents that may be suitable for certainembodiments include, but are not limited to, methanol, ethanol, ethyleneglycol, xylene, toluene, aromatics, butyl glycol, and any combinationthereof. In certain embodiments, the solutions comprising the polymericadditive or the surfactant, or the solutions or treatment fluidscomprising the MSCs, may further comprise one or more salts, among otherreasons, to facilitate the formation and/or maintenance of the MSCs. Inthese embodiments, any salt known in the art (e.g., NaCl) may be used.

The methods and systems of the present disclosure may be used to formcompositions (e.g., treatment fluids) that may be used to treat aportion of a subterranean formation. The treatment fluids of the presentdisclosure generally comprise an aqueous base fluid and one or moreMSCs. The aqueous base fluid used in some embodiments of the treatmentfluids of the present disclosure may comprise fresh water, saltwater(e.g., water containing one or more salts dissolved therein), brine(e.g., saturated saltwater), seawater, or any combination thereof.Generally, the water may be from any source, provided that it does notcontain components that might adversely affect the stability of thetreatment fluids of the present disclosure. One of ordinary skill in theart, with the benefit of this disclosure, will recognize what componentsmight adversely affect the stability and/or performance of the treatmentfluids of the present disclosure.

In forming a treatment fluid comprising MSCs of the present disclosure,the MSCs may be included in an amount sufficient to release a sufficientamount of surfactant and polymeric additive to perform the desiredtreatment in the subterranean formation (e.g., to form one or morerelatively short-lived oil-in-acid or oil-in-water emulsions within asubterranean formation). For example, in some embodiments, sufficientMSCs may be included in the treatment fluid to release an amount ofsurfactant of from about 0.1 to 50 gallons of surfactant per thousandgallons of acid, water, and/or other aqueous base fluid (“gpt”), or putanother way, approximately 100 to 50,000 ppm. In other exampleembodiments, sufficient MSCs may be included in the treatment fluid torelease an amount of surfactant of from about 2 to 40 gpt (approximately2,000 ppm to 40,000 ppm), or in other embodiments, from about 3 to 25gpt (approximately 3,000 ppm to about 25,000 ppm). In some embodiments,sufficient MSCs may be included in the treatment fluid to release anamount of surfactant of from about 4 gpt to about 18 gpt (approximately4,000 ppm to 18,000 ppm).

The treatment fluids of the present disclosure may optionally includeother components such as acids, salts, solvents, particulates, or othercompounds as long as these components do not interfere with thesurfactant or the ability of the polymeric additive to delay release ofthe surfactant. A person of skill in the art with the benefit of thisdisclosure would be able to select the appropriate other componentsdepending on the desired treatment fluid. For example, the person ofskill in the art might include an acid if it is desired to produce anacidizing treatment fluid. A person of skill in the art might alsoinclude particulates if it is desired to produce a fracturing fluid withproppant particles.

The treatment fluids of some embodiments may include solvents, such asmethanol, ethanol, ethylene glycol, xylene, toluene, aromatics, or butylglycol. Thus, for example, a treatment fluid of some embodiments mayinclude ethylene glycol mono-butyl ether. The treatment fluids of someembodiments may further include salts, among other reasons, to stabilizethe MSCs.

The treatment fluids of some embodiments may further comprise additionalsurfactants (e.g., in addition to the surfactants provided in the MSCs),among other reasons, to lower the surface tension or capillary pressureof the treatment fluid and allow the fluid to penetrate deeper into aformation or fracture therein. In certain embodiments, the additionalsurfactant may be included in the treatment fluid in a concentrationgreater than the critical micelle concentration (CMC) of that surfactantin the fluid.

The treatment fluids of some embodiments may include particulates (suchas proppant particulates or gravel particulates) suitable for use insubterranean applications. Particulates suitable for use in the presentdisclosure may comprise any material suitable for use in subterraneanoperations. Proppant particulates may be used in conjunction withhydraulic fracturing to prevent the fractures from fully closing uponthe release of hydraulic pressure, forming conductive channels throughwhich fluids may flow to the wellbore. Suitable particulate materialsinclude, but are not limited to, sand, bauxite, ceramic materials, glassmaterials, polymer materials, Teflon® materials, nut shell pieces, curedresinous particulates comprising nut shell pieces, seed shell pieces,cured resinous particulates comprising seed shell pieces, fruit pitpieces, cured resinous particulates comprising fruit pit pieces, wood,composite particulates, and any combination thereof. Suitable compositeparticulates may comprise a binder and a filler material whereinsuitable filler materials include silica, alumina, fumed carbon, carbonblack, graphite, mica, titanium dioxide, meta-silicate, calciumsilicate, kaolin, talc, zirconia, boron, fly ash, hollow glassmicrospheres, solid glass, and any combination thereof. The particulatesize generally may range from about 2 mesh to about 400 mesh on the U.S.Sieve Series; however, in certain circumstances, other sizes may bedesired and will be entirely suitable for practice of the presentdisclosures. In particular embodiments, preferred particulates sizedistribution ranges are one or more of 6/12, 8/16, 12/20, 16/30, 20/40,30/50, 40/60, 40/70, or 50/70 mesh. It should be understood that theterm “particulate,” as used in this disclosure, includes all knownshapes of materials, including substantially spherical materials,fibrous materials, polygonal materials (such as cubic materials), andmixtures thereof. Moreover, fibrous materials, that may or may not beused to bear the pressure of a closed fracture, are often included infracturing and sand control treatments. In certain embodiments, theparticulates included in the treatment fluids of some embodiments of thepresent disclosure may be coated with any suitable resin or tackifyingagent known to those of ordinary skill in the art.

The treatment fluids of some embodiments may additionally or insteadinclude one or more of a variety of well-known additives (in addition tothe polymeric additives included in the MSCs), such as gel stabilizers,fluid loss control additives, scale inhibitors, organic corrosioninhibitors, catalysts, clay stabilizers, biocides, bactericides,friction reducers, gases, foaming agents, iron control agents,solubilizers, pH adjusting agents (e.g., buffers), and the like. Thoseof ordinary skill in the art, with the benefit of this disclosure, willbe able to determine the appropriate additives for a particularapplication.

The MSCs and the treatment fluids of the present disclosure may beprepared at a well site or at an offsite location. In certainembodiments, a base fluid may be mixed with a viscosifying agent first,among other reasons, in order to allow the viscosifying agent tohydrate. Then, proppants, MSCs, and/or other additives may be mixed intothe viscosified fluid. Once prepared, a treatment fluid of the presentdisclosure may be placed in a tank, bin, or other container for storageand/or transport to the site where it is to be used. In otherembodiments, a treatment fluid of the present disclosure may be preparedon-site, for example, using continuous mixing or “on-the-fly” methods,as described below.

The present disclosure in some embodiments provides methods for usingthe treatment fluids to carry out a variety of subterranean treatments,including but not limited to, hydraulic fracturing treatments, enhancedoil recovery treatments (e.g., water flooding treatments, polymerflooding treatments, etc.), acidizing treatments, and drillingoperations. In some embodiments, the treatment fluids of the presentdisclosure may be used in treating a portion of a subterraneanformation, for example, in acidizing treatments such as matrix acidizingor fracture acidizing. In certain embodiments, a treatment fluid may beintroduced into a subterranean formation. In some embodiments, thetreatment fluid may be introduced into a well bore that penetrates asubterranean formation. In some embodiments, the treatment fluid may beintroduced at a pressure sufficient to create or enhance one or morefractures within the subterranean formation (e.g., hydraulicfracturing).

In some embodiments, the treatment fluid further comprising an acid maybe introduced at a pressure sufficient to cause at least a portion ofthe treatment fluid to penetrate at least a portion of the subterraneanformation, and the treatment fluid may be allowed to interact with thesubterranean formation so as to create one or more voids in thesubterranean formation (for example, in acidizing treatments).Introduction of the treatment fluid may in some of these embodiments becarried out at or above a pressure sufficient to create or enhance oneor more fractures within the subterranean formation (e.g., fractureacidizing). In other embodiments, introduction of the treatment fluidmay be carried out at a pressure below that which would create orenhance one or more fractures within the subterranean formation (e.g.,matrix acidizing).

Referring now to FIG. 1, an example of a well bore treatment system 10is illustrated according to certain embodiments of the presentdisclosure. System 10 includes a stop-flow mixing apparatus 20, alow-dose pumping apparatus 29, a base fluid source 30, a proppant source40, and a pump and blender system 50, and is disposed at the surface ata well site where a well 60 is located. System 10 may be used to prepareMSCs and/or treatment fluids according to the present disclosure and tointroduce those fluids into well 60. The various apparatus in system 10may be provided at the well site as separate components or equipment, ormay be integrated in a single unitary system such as a fracturingblender vehicle. The stop-flow mixing apparatus 20 according to someembodiments is illustrated in further detail in FIG. 2. In certainembodiments, stop-flow mixing apparatus 20 may include similarcomponents to that of laboratory stop-flow mixing apparatuses that areconstructed at appropriate scales and with appropriate materials for awell site application. Referring now to FIG. 2, stop-flow mixingapparatus 20 includes at least two syringes 22 and 23 that inject fluids(e.g., solutions comprising surfactant or polymeric additive) into oneor more inlets 24 a and 24 b in mixer 24. Mixer 24 may comprise anymixer, homogenizer, or dispersion device that provides sufficient shearto mix relatively small volumes of fluids, including but not limited tohigh energy mixing devices and ultrasonic dispersion devices. The mixerincludes an outlet 24 c through which fluid may flow to an observationcell 26 (through its inlet 26 a) and stopping syringe 25. In certainembodiments, as the solutions comprising the surfactant and polymericadditive are pushed from syringes 22 and 23, respectively, and throughmixer 24, the molecules of the surfactant and polymeric additiveassociate to form MSCs. Fluid comprising the MSCs then flows intoobservation cell 26 and stopping syringe 25 until stopping syringe 25reaches a predetermined volume (e.g., when the reaction reaches acontinuous flow rate). At that volume, the plunger on stopping syringewill stop the flow of liquids through the apparatus 20. Apparatus 20also includes a measurement device 27 that is configured to monitor thecontents of the observation cell 26 using one or more known analyticalmethods (e.g., UV-visible spectroscopy, FTIR spectroscopy, etc.) andequipment. This device may be used, among other purposes to confirm theformation of MSCs for use in the treatment fluid. The fluid inobservation cell 28 then flows out of the stop-flow mixing apparatus 20through outlet 26 b. In certain embodiments, the stop-flow mixingapparatus illustrated in FIG. 2 (or another suitable device for formingMSCs of the present disclosure) may be located and operated at alocation other than a well site, and the MSCs formed using thatapparatus may be transported to a well site for use.

Referring back to FIG. 1, fluids comprising MSCs flow out of stop-flowmixing apparatus 20, and are then metered into pump and blender system50 using a low-dose pumping apparatus 29 coupled between stop-flowmixing apparatus 20 and an inlet of pump and blender system 50. Thelow-dose pumping apparatus 29 may comprise any liquid dosing or meteringpump known in the art that is capable of pumping liquids therethrough invery low concentrations (e.g., less than about 1 gallon per thousandgallons of fluid (gpt), or in some cases, less than about 0.1 gpt).Examples of such devices are pumps equipped with the Micro Motion®meters and measurement devices available from Emerson ProcessManagement.

The proppant source 40 can include a proppant for combination with thefracturing fluid. The pump and blender system 50 receives the base fluid(and any additives pre-mixed into that fluid) from fluid source 30 andcombines it with other components, including proppant from the proppantsource 40. System 10 optionally may include other tanks, hoppers, orpumps (not shown) that are equipped to dispense additional fluids and/oradditives 70 into pump and blender system 50. The resulting mixture maybe pumped down the well 60, for example, under a pressure sufficient tocreate or enhance one or more fractures in a subterranean zone, forexample, to stimulate production of fluids from the zone. Notably, incertain instances, stop-flow mixing apparatus 20, base fluid source 30,and/or proppant source 40 may be equipped with one or more meteringdevices (not shown) to control the flow of fluids, proppants, and/orother compositions to the pump and blender system 50. Such meteringdevices may permit the pump and blender system 50 can source from one,some or all of the different sources at a given time, and may facilitatethe preparation of treatment fluids in accordance with the presentdisclosure using continuous mixing or “on-the-fly” methods.

FIG. 3 shows the well 60 and treatment system 10 during a fracturingoperation in a portion of a subterranean formation of interest 102surrounding a well bore 104. The well bore 104 extends from the surface106, and the fracturing fluid 108 is applied to a portion of thesubterranean formation 102 surrounding the horizontal portion of thewell bore. Although shown as vertical deviating to horizontal, the wellbore 104 may include horizontal, vertical, slant, curved, and othertypes of well bore geometries and orientations, and the fracturingtreatment may be applied to a subterranean zone surrounding any portionof the well bore. The well bore 104 can include a casing 110 that iscemented or otherwise secured to the well bore wall. The well bore 104can be uncased or include uncased sections. Perforations can be formedin the casing 110 to allow fracturing fluids and/or other materials toflow into the subterranean formation 102. In cased wells, perforationscan be formed using shape charges, a perforating gun, hydro-jettingand/or other tools.

The well is shown with a work string 112 depending from the surface 106into the well bore 104. The pump and blender system 50 is coupled a workstring 112 to pump the fracturing fluid 108 into the well bore 104. Theworking string 112 may include coiled tubing, jointed pipe, and/or otherstructures that allow fluid to flow into the well bore 104. The workingstring 112 can include flow control devices, bypass valves, ports, andor other tools or well devices that control a flow of fluid from theinterior of the working string 112 into the subterranean zone 102. Forexample, the working string 112 may include ports adjacent the well borewall to communicate the fracturing fluid 108 directly into thesubterranean formation 102, and/or the working string 112 may includeports that are spaced apart from the well bore wall to communicate thefracturing fluid 108 into an annulus in the well bore between theworking string 112 and the well bore wall.

The working string 112 and/or the well bore 104 may include one or moresets of packers 114 that seal the annulus between the working string 112and well bore 104 to define an interval of the well bore 104 into whichthe fracturing fluid 108 will be pumped. FIG. 3 shows two packers 114,one defining an uphole boundary of the interval and one defining thedownhole end of the interval. When the fracturing fluid 108 isintroduced into well bore 104 (e.g., in FIG. 3, the area of the wellbore 104 between packers 114) at a sufficient hydraulic pressure, one ormore fractures 116 may be created in the subterranean zone 102. Theproppant particulates in the fracturing fluid 108 may enter thefractures 116 where they may remain after the fracturing fluid flows outof the well bore. These proppant particulates may “prop” fractures 116such that fluids may flow more freely through the fractures 116.

While not specifically illustrated herein, the disclosed methods andcompositions may also directly or indirectly affect any transport ordelivery equipment used to convey the compositions to the fracturingsystem 10 such as, for example, any transport vessels, conduits,pipelines, trucks, tubulars, and/or pipes used to fluidically move thecompositions from one location to another, any pumps, compressors, ormotors used to drive the compositions into motion, any valves or relatedjoints used to regulate the pressure or flow rate of the compositions,and any sensors (i.e., pressure and temperature), gauges, and/orcombinations thereof, and the like.

To facilitate a better understanding of the present disclosure, thefollowing examples of certain aspects of preferred embodiments aregiven. The following examples are not the only examples that could begiven according to the present disclosure and are not intended to limitthe scope of the disclosure or claims.

EXAMPLES Example 1A

Dynamic surface tension tests were performed to determine how the MSCsof the present disclosure impact the surface tension of the associatedsurfactants at the air-water interface. In these tests, tensiometer wasused to determine the requisite pressure of a gas (air) pumped into acapillary needle projecting into a solution of the surfactant/MSC's ofthe present disclosure to create a bubble in the solution. Using themaximum bubble pressure method, the pressure needed to form a bubble ismeasured and the surface tension of the sample is calculated from thepressure difference between inside and outside the bubble and the radiusof the bubble. Aqueous solutions of two different anionic surfactantswere tested in this manner, both in samples with the surfactants alone(samples S1 and S2) and samples with the surfactants associated withmulti-functional surfactant complexes (samples MSC1 and MSC2). Thesurfactant in samples S1 and MSC1 comprised a DDBSA anionic surfactant,and the surfactant in samples S2 and MSC2 comprised a blend of DDBSA andethoxylated surfactants. In samples MSC1 and MSC2, a polyethyleneminecationic polymer was used to form the multi-functional surfactantcomplexes. FIG. 4 is a dynamic surface tension plot illustrating thisdata over time. As shown in FIG. 4, the dynamic surface tension of thesolutions containing MSCs maintained a high surface tension for a longerperiod of time and initially decreased less rapidly than thecorresponding solutions of those surfactants alone. The rate of decreasein the surface tension corresponds to the diffusion of the surfactant tothe air-water surface.

Example 1B

Dynamic surface tension tests similar to those described in Example 1were performed on a solution of a DDBSA anionic surfactant (sample S3)as well as a series of solutions of MSCs of that anionic surfactant withdifferent concentrations of a dodecyl trimethyl ammonium chloride (C-12TMAC) cationic polymeric clay stabilizer additive (samples MSC3, MSC4,MSC5, and MSC6). FIG. 5 is a dynamic surface tension plot illustratingthis data over time. As shown in FIG. 5, similar to the solutions testedin Example 1A, the dynamic surface tension of the solutions containingMSCs maintained a high surface tension for a longer period of time andinitially decreased less rapidly than the corresponding solution of thesurfactant alone, indicating a lower diffusion rate of the surfactant.As shown in FIG. 5, solutions comprising the MSCs exhibit a furtherreduced surface tension of the solution (i.e., below that of thesolution with surfactant alone) after all of the surfactant wasreleased, which is a result of the oppositely-charged polymeric additivein those solutions released from the MSCs.

The data from Examples 1A and 1B demonstrates that, in certainembodiments where these MSCs of the present disclosure are included inan aqueous fluid that is pumped into a well, the surfactant in the MSCmay remain in solution for a longer period of time than a solution ofthe corresponding surfactant alone, instead of adsorbing onto proppants,well bore equipment, or other surfaces in the subterranean formation orwell bore. Moreover, it is noted that, for the surfactant in samplesMSC1 and S1, the surface tension of the solution with MSCs eventuallyreaches the same value as the solution without MSCs, indicating that theentire surface is occupied by surfactant released from the MSCs.

Example 2

Dynamic interfacial tension tests were also performed to determine howthe MSCs of the present disclosure impact the surface tension of theassociated surfactants at the oil-water interface. In these tests, afresh oil droplet was created in a U-shaped needle and an aqueouscontinuous phase. The dynamic interfacial tension was obtained from thependant shape of the drop using the Young-Laplace equation. Aqueoussolutions of two different anionic surfactants were tested in thismanner, both in samples with the surfactants alone (samples S1 and S2)and samples with the surfactants associated with multi-functionalsurfactant complexes (samples MSC1 and MSC2). FIGS. 6A and 6B areinterfacial tension plots illustrating this data over time for S1/MSC1and S2/MSC2, respectively. As shown in FIGS. 6A and 6B, the interfacialtension decay rate for the solutions of surfactants alone was higherthan that of the solutions containing MSCs, and the interfacial tensionof the solutions containing surfactants alone began to decay sooner thanin the solutions containing MSCs. This data demonstrates that, incertain embodiments where these MSCs of the present disclosure areincluded in an aqueous fluid that is pumped into an oil reservoir, oncepumping is stopped, the surfactant molecules will still reach out to oilmolecules in contact with the aqueous fluid and the surfactant inventoryin the aqueous fluid will not deplete with time.

Example 3

Oil recovery tests were also performed using an aqueous solution of ananionic surfactant (comprising a blend of DDBSA and ethoxylatedsurfactants) and an aqueous solution of a corresponding MSC of thatanionic surfactant with a poly-DADMAC cationic polymer. Concentrationsof 1 gallon per thousand gallons (gpt) and 2 gpt of each type ofsolution were tested (the concentration referring to the surfactant orthe MSC). Each solution was pumped into an high-performance liquidchromatography (HPLC) column packed with 100 mesh core powders that hadbeen aged with crude oil at reservoir temperature for two days. Thesolutions were injected at a fixed flow rate of 3 ml/hr. The second passof the effluent solution was analyzed using an InfraCal analyzer(available from Spectro Scientific of Chelmsford, MA) to determine theoil recovery. The percentage of oil recovered in each of these tests wasrecorded and is shown in FIG. 7. As shown, the solutions of MSCsgenerally achieved increased oil recovery as compared to thecorresponding solutions of the surfactant alone.

Therefore, the present disclosure is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. While numerous changes may be made bythose skilled in the art, such changes are encompassed within the spiritof the subject matter defined by the appended claims. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered or modified and all such variations are considered within thescope and spirit of the present disclosure. In particular, every rangeof values (e.g., “from about a to about b,” or, equivalently, “fromapproximately a to b,” or, equivalently, “from approximately a-b”)disclosed herein is to be understood as referring to the power set (theset of all subsets) of the respective range of values. The terms in theclaims have their plain, ordinary meaning unless otherwise explicitlyand clearly defined by the patentee.

What is claimed is:
 1. A method comprising: providing a first solutioncomprising at least one surfactant and a second solution comprising atleast one polymeric additive, wherein the surfactant and the polymericadditive carry opposite charges; using a stop-flow mixing apparatus at awell site to mix the first and second solutions to form one or moremulti-functional surfactant complexes that comprise the surfactant andthe polymeric additive; using a low-dose pumping apparatus at the wellsite to transfer the one or more multi-functional surfactant complexesfrom the stop-flow mixing apparatus to a blending apparatus at the wellsite; using the blending apparatus to mix the one or moremulti-functional surfactant complexes with an aqueous base fluid to forma treatment fluid; and introducing the treatment fluid into a well boreat the well site penetrating at least a portion of a subterraneanformation.
 2. The method of claim 1 wherein the treatment fluid is afracturing fluid, and the fracturing fluid is introduced into the wellbore at a pressure sufficient to create or enhance one or more fractureswithin the subterranean formation.
 3. The method of claim 1 wherein: thestop-flow mixing apparatus comprises an observation cell into which thefirst and second solutions flow after mixing, and a measurement deviceconfigured to monitor the contents of the observation cell, and themethod further comprises using the measurement device to confirm thepresence of one or more multi-functional surfactant complexes in theobservation cell.
 4. The method of claim 3 wherein the measurementdevice comprises a UV-visible spectrometer.
 5. The method of claim 1further comprising using the blending apparatus to mix a plurality ofproppant particulates with the one or more multi-functional surfactantcomplexes and the aqueous base fluid to form the treatment fluid.
 6. Themethod of claim 1 wherein the blending apparatus comprises a pump andblending system, and the treatment fluid is introduced into the wellbore using the pump and blending system.
 7. The method of claim 1wherein the surfactant comprises at least one surfactant selected fromthe group consisting of: a sodium, potassium, or ammonium salt of a longchain alkyl sulfonate; a sodium, potassium, or ammonium salt of a longchain alkyl aryl sulfonate; a dialkyl sodium sulfosuccinate; an alkylsulfate; an alkyl sulfonate; an alkoxylated sulfate; an ethoxylatedalcohol; a polyglucoside; an ethoxylated long-chain alcohol; an alkylammonium bromide; a hydroxysultaine; and any combination thereof.
 8. Themethod of claim 1 wherein the polymeric additive comprises at least onepolymeric additive selected from the group consisting of: a frictionreducer; a clay stabilizer; a biocide; a corrosion inhibitor; a scaleinhibitor; and any combination thereof.
 9. The method of claim 1 whereinthe polymeric additive comprises a clay stabilizer.
 10. The method ofclaim 1 wherein the polymeric additive is cationic and the surfactant isanionic.
 11. The method of claim 1 wherein the treatment fluid furthercomprises one or more salts.
 12. The method of claim 1 wherein thetreatment fluid further comprises one or more additional surfactants.13. A system for preparing multi-functional surfactant complexes at awell site comprising: a pump and blender system disposed at a surface ofa well bore penetrating at least a portion of a subterranean formation;a stop-flow mixing apparatus having at least a first inlet for receivinga solution comprising a surfactant, a second inlet for receiving asolution comprising a polymeric additive, and an outlet through which asolution comprising one or more multi-functional surfactant complexesflows out of the stop-flow mixing apparatus; a low-dose pumpingapparatus coupled between the outlet of the stop-flow mixing apparatusand an inlet of the pump and blender system; and a base fluid sourcecoupled to an inlet of the pump and blender system.
 14. The system ofclaim 13 further comprising a proppant source coupled to an inlet of thepump and blender system.
 15. The system of claim 13 wherein thestop-flow mixing apparatus further comprises an observation celldisposed between the outlet and the first and second inlets throughwhich a solution mixed by the stop-flow mixing apparatus flows, and ameasurement device configured to monitor the contents of the observationcell.
 16. The system of claim 15 wherein the measurement devicecomprises a UV-visible spectrometer.
 17. A method comprising: providinga treatment fluid comprising an aqueous base fluid and one or moremulti-functional surfactant complexes that comprise at least onesurfactant and at least one polymeric additive, wherein the surfactantand the polymeric additive carry opposite charges; and introducing thetreatment fluid into a well bore at a well site penetrating at least aportion of a subterranean formation.
 18. The method of claim 17 whereinthe step of providing the treatment fluid comprises: using a low-dosepumping apparatus at the well site to transfer the one or moremulti-functional surfactant complexes into a blending apparatus at thewell site; and using the blending apparatus to mix the one or moremulti-functional surfactant complexes with an aqueous base fluid to forma treatment fluid.
 19. The method of claim 17 wherein the polymericadditive comprises a clay stabilizer.
 20. The method of claim 17 whereinthe polymeric additive is cationic and the surfactant is anionic.